The invention relates generally to data telemetry methods and apparatus used with measurement-while-drilling (MWD) and logging-while-drilling (LWD) systems. More particularly, the invention relates to a method and apparatus for reducing the effects of harmonically-related tone noise, especially noise from mud pumps, that is intended to improve signal detection in the telemetry used with MWD and LWD systems.
MWD and LWD systems provide drilling operators greater control over the construction of a well by providing information about conditions at the bottom of a wellbore substantially in real time as the wellbore is being drilled. Certain information is of interest to drilling operators, which is preferably obtained from the bottom of the wellbore substantially in real time. This information includes directional drilling variables such as inclination and direction (azimuth) of the drill bit, and geological formation data, such as natural gamma ray radiation levels and electrical resistivity of the rock formation. Typically, MWD tools or instruments make the directional and other drilling-related measurements, and LWD tools or instruments make the geological formation measurements. Often MWD and LWD tools are integrated into a single instrument package and are called MWD/LWD tools. In the description which follows, the term xe2x80x9cMWD systemxe2x80x9d will be used collectively to refer to MWD, LWD, and combination MWD/LWD tools or instruments. The term MWD system should also be understood to encompass equipment and techniques for data transmission from within the well to the earth""s surface.
MWD systems measure parameters (such as the previously mentioned examples) within the wellbore, and can transmit the acquired data to the earth""s surface from within the wellbore. There are several different methods for transmitting data to the surface, including xe2x80x9cmud pulsexe2x80x9d telemetry and electromagnetic telemetry.
In mud-pulse telemetry, data is transmitted from the MWD system in the wellbore to the surface by means of generating pressure waves in the drilling fluid (drilling xe2x80x9cmudxe2x80x9d) that is pumped through the drill string by pumps on the surface. FIG. 1 illustrates a drilling system 100 that is equipped for MWD system operation using mud-pulse telemetry. As shown in FIG. 1, the drilling system 100 includes a drill string 112 hanging from a derrick 150. The drill string 112 extends through a rotary table 152 on the rig floor 151 into the wellbore 121. A drill bit 111 is attached to the end of the drill string 112. Drilling is accomplished by rotating the drill bit 111 while some of the weight of the drill string 112 is applied to the bit. The drill bit 111 may be rotated by rotating the entire drill sting 112 from the surface using the rotary table 152 which is adapted to drive a kelly 153, or alternatively by using a top drive (not shown). Alternatively, operating a positive displacement motor known as a xe2x80x9cmud motorxe2x80x9d 110 disposed in the drill string 112 above the drill bit 111, drilling can be accomplished without rotating the entire drill string 112.
While drilling, drilling mud is pumped by mud pumps 115 on the surface through surface piping 117, standpipe 118, rotary hose 119 and swivel 154, kelly 153 and down the drill string 112. Pulsation dampeners 116, also known as desurgers or accumulators, are located near the outputs of the mud pumps 115 to smooth pressure transients in the mud discharged from the mud pumps 115. The mud in the drill string 112 is forced out through jet nozzles (not shown) in the cutting face of the drill bit 111. The mud is returned to the surface through an annular space (the well annulus 113) between the well 121 and the drill string 112. One or more sensors or transducers 101 are located in a measurement module 102 in a bottomhole assembly portion of the drill string 112 to measure selected downhole conditions. For example, the transducer 101 may be a strain gage that measures weight-on bit (axial force applied to the bit 111) or a thermocouple that measures temperature at the bottom of the well 121. Additional sensors may be provided as necessary to measure other drilling and formation parameters such as those previously described.
The measurements made by the transducers 101 may be transmitted to the surface through the drilling mud in the drill string 112. To do this, first, the transducers 101 send signals that are representative of the measured downhole condition to a downhole electronics unit 103. The signals from the transducers 101 may be digitized in an analog-to-digital converter (not shown separately). The downhole electronics unit 103 then collects the measurements from the transducers 101 and arranges them into a selected telemetry format, usually a digital representation of the measurements made by the transducers 101. Extra digital bits used for synchronization, and error detection and correction may be added to the telemetry format. The telemetry format is then passed to a modulator 104, which groups bits into symbols and then uses a process called modulation to impress the symbols onto a baseband or carrier waveform that can be transmitted through the mud in the drill string 112. A symbol consists of a group of one or more bits. The modulated signals serve as input to an acoustic xe2x80x9ctransmitterxe2x80x9d 105 and valve mechanism 106 that generates a telemetry pressure wave that ultimately carries data to the surface. One or more pressure transducers 130, 132 located on the standpipe 118, or surface piping 117, generate signals that are representative of variations in the pressure of the mud. The outputs 131, 133 of the pressure transducers 130, 132 can be digitized in analog-to-digital converters and processed by a signal processing module 134, which recovers the symbols from the pressure variations and then sends data recovered from the symbols to a computer 135 where the transmitted information can be accessed by the drilling operators.
There are several mud-pulse telemetry systems known in the art. These include positive-pulse, negative-pulse, and continuous-wave. In a positive-pulse system, valve mechanism 106 of the transmitter 105 creates a pressure pulse at higher pressure than that of the drilling mud by momentarily restricting flow in the drill string 112. In a negative mud-pulse telemetry system, the valve mechanism 106 creates a pressure pulse at lower pressure than that of the mud by venting a small amount of the mud in the drill string 112 through a valve 106 to the well annulus 113. In both the positive-pulse and negative-pulse systems, the pressure pulses propagate to the surface through the drilling mud in the drill string 112 and are detected by the pressure transducers 130, 132. To send a stream of data, a series of pressure pulses are generated in a pattern that is recognizable by the signal processing module 134.
The pressure pulses generated by positive-pulse and negative-pulse systems are discrete pressure waves. Continuous wave telemetry can be generated with a rotary valve or xe2x80x9cmud siren.xe2x80x9d In a continuous-wave system, the valve mechanism 106 rotates so as to repeatedly interrupt the flow of the drilling mud in the drill string 112. This causes a periodic pressure wave to be generated at a rate that is proportional to the rate of interruption. Information is then transmitted by modulating the phase, frequency, or amplitude of the periodic wave in a manner related to the downhole measured data.
The telemetry pressure wave that carries information from the transmitter 105 to the pressure transducers 130, 132 is subjected to attenuation, reflections, and noise as it moves through the drilling mud. The signal attenuation as it passes through the mud channel may not be constant across the range of component frequencies present in the telemetry pressure wave. Typically, lower frequency components are subject to less attenuation than higher frequency components. The pressure waves are also reflected off the bottom of the well, and are at least partially reflected at any acoustic impedance mismatches in the drill string 112 and the surface mud system, i.e., the mud pumps 115, surface piping. 117, standpipe 118, rotary hose 119, swivel 154, and pulsation dampeners 116. As a result, the signal pressure wave arriving at the pressure transducer 130, 132 on the standpipe 118 is the superposition of the main wave from the transmitter 105 and multiple reflected waves. The result of the reflections and frequency dependent attenuation is that each of the transmitted symbols become spread out in time and interfere with symbols preceding and following those transmitted symbols. This is known in the digital communications art as intersymbol interference (ISI).
Pressure waves from the surface mud pumps 115 contribute considerable amounts of noise. The pump noise is mainly the result of reciprocating motion of mud pump pistons and is harmonic in nature. The pressure waves from the mud pumps 115 travel in the opposite direction from the main information carrying wave, namely from the surface down the drill string 112 to the drill bit 111. The pressure transducers 130, 132 detect pressure variations representative of the sum of signal waves and noise waves. Components of the noise from the surface mud pumps 115 may be present within the frequency range used for transmission of the telemetry wave. In some cases the components of the mud pump 115 noise waves may have considerably greater power than the received telemetry wave, making correct detection of the received symbols very difficult. Additional downhole sources of noise can include the drilling motor 110, and drill bit 111 interaction with formation being drilled. All these factors degrade the quality of the received pressure signal and make it difficult to recover the transmitted information.
Mechanical vibration of the rig 150 and electrical noise coupling onto the electrical wiring that carries the electrical signals from the sensors 130, 132 to the signal receiver 134 on the surface may also degrade the reception of the wanted telemetry signal.
Attempts to find solutions for reducing interfering effects in MWD telemetry signals are not new and many techniques have been proposed. Most of these techniques concentrate on reducing the interference from mud pump noise. For example, U.S. Pat. No. 3,302,457 issued to Mayes discloses a scheme for reducing mud pump noise based on combining the outputs of a static pressure sensor and a differential pressure sensor. U.S. Pat. No. 3,555,504 issued to Fields discloses a method using two pressure taps at spaced points on the surface piping. The pressure taps are connected to flow lines which delay the pressure wave from one tap relative to the other so that the pump noise components from both taps would be in phase at a differential pressure meter, thus canceling the pump noise. U.S. Pat. No. 3,488,629 issued to Claycomb discloses an extension to the technique disclosed in the Fields ""504 patent, including check valves in the flow lines to reduce reflected waves in the flow lines.
U.S. Pat. No. 3,747,059 issued to Garcia discloses an electronic noise filter system that eliminates spurious detection caused by mud pump noise waves reflecting back off the rotary hose. The electronic noise filter system is coupled to at least two pressure-sensitive transducers located at spaced points on the mud pump side of the flexible hose. Electronic circuits in the electronic noise filter system introduce relative delays as well as amplitude and phase adjustments to the signals detected by the transducers. After the delays and the amplitude and phase adjustments, the mud pump noise components of the signals are aligned in phase and can be subtracted, leaving only the signal from downhole. U.S. Pat. No. 3,716,830 issued to Garcia discloses an alternative system that eliminates spurious detection caused by mud pump noise waves reflecting back off the rotary hose by placing one of the transducers after the rotary hose on the side furthest away from the mud pumps. The systems disclosed in the Garcia ""830 patent only reduce the effect of mud pump noise wave reflecting off the rotary hose; other reflections or distortions of the noise or signal waves are not addressed.
U.S. Pat. No. 3,742,443 issued to Foster et al. discloses a noise reduction system that uses two pressure sensors at spaced apart positions. The optimum spacing of the sensors is one-quarter wavelength at the frequency of the telemetry signal carrier. The signal from the sensor closer to the mud pumps is passed through a fitter having characteristics related to the amplitude and phase distortion encountered by the mud pump noise component as it travels between the two spaced points. The filtered signal is delayed and then combined with the signal derived from the sensor further away from the mud pumps. Combining the signals results in destructive interference of the mud pump noise, and constructive interference of the telemetry signal wave, because of the one-quarter wavelength separation between the sensors. The combined output is then passed through another filter to reduce distortion introduced by the signal processing and combining operation. The system does not account for distortion introduced in the telemetry signal wave as it travels through the mud column from the downhole transmitter to the surface sensors. The filter on the combined output also assumes that the mud pump noise wave traveling from the mud pumps between the two sensors encounters the same distortion mechanisms as the telemetry signal wave traveling in the opposite direction between the same pair of sensors. This assumption does not, however, always hold true in actual MWD systems.
U.S. Pat. No. 4,215,425 issued to Waggener discloses a coherent phase shift keying (PSK) demodulation system that includes a differential filtering operation for mud pump noise cancellation using two sensors separated by one-quarter wavelength U.S. Pat. No. 4,262,343 issued to Claycomb discloses a system in which signals from a pressure sensor and a fluid velocity detector are combined to cancel mud pump noise and enhance the signal from downhole. U.S. Pat. No. 4,590,593 issued to Rodney discloses a two sensor noise canceling system similar to those of Garcia and Foster et al., but which includes a variable delay. The delay is determined using a least mean squares algorithm during the absence of downhole data transmission.
U.S. Pat. No. 4,642,800 issued to Umeda discloses a noise-reduction scheme that includes obtaining an xe2x80x9caverage pump signaturexe2x80x9d by averaging over a certain number of pump cycles. The assumption is that the telemetry signal is not periodic with the same period as the pump noise and, hence, will average to zero. The pump signature is then subtracted from the incoming signal to leave a residual that should contain mostly telemetry signal. U.S. Pat. No. 5,146,433 issued to Kosmala et al uses signals from position sensors on the mud pumps as inputs to a system that relates the mud pump pressure to the position of the pump pistons. Thus, the mud pump noise signature is predicted from the positions of the pump pistons. The predicted pump noise signature is subtracted from the received signal to cancel the pump noise component of the received signal.
U.S. Pat. No. 4,715,022 issued to Yeo discloses a signal detection method for mud pulse telemetry systems using a pressure transducer on the gas filled side of the pulsation dampener to improve detection of the telemetry wave in the presence of mud pump noise. One of the disclosed embodiments therein includes a second pressure transducer disposed on the surface pipes between the dampener and the drill string, and a signal conditioner to combine the signals from the two transducers.
U.S. Pat. No. 4,692,911 issued to Scherbatskoy discloses a scheme for reducing mud pump noise by subtracting from the received standpipe pressure signal, the signal that was received T seconds previously, where T represents the period of the pump strokes. The received standpipe pressure signal comes from a single transducer. A delay line is used to store the delayed standpipe pressure signal and this is then subtracted from the current standpipe pressure signal. This forms a comb filter with notches at integer multiples of the pump stroke rate. The telemetry signal then needs to be recovered from the output of the subtraction operation, that includes the telemetry signal plus delayed copies of the telemetry signal.
A control signal must be obtained that controls the delay T. The control signal may be obtained from a mechanical sensor, placed on the mud pump, that produces pulses at a rate proportional to the stroke rate of the mud pump. In an alternative embodiment the timing control signal is extracted from the standpipe pressure signal. The timing pulses for determining the delay T are produced by a phase-locked loop that tracks the 512 harmonic of the mud pumps. U.S. Pat. No. 4,866,680 issued to Scherbatskoy discloses an enhancement of the method disclosed in the Scherbatskoy ""911 patent, which includes the use of a Wiener filter (effectively a linear equalizer) to reduce the telemetry signal distortion caused by the subtraction operation that is used to reduce the mud pump noise.
U.S. Pat. No. 4,730,281 issued to Rodney discloses an adaptive bucket brigade filter with a feedback loop in place of the delay used by Scherbatskoy to produce a comb filter response that removes a periodic noise and its harmonics while also reducing the delayed copies of the telemetry signal caused by the comb filter response.
U.S. Pat. No. 4,878,206 issued to Grosso et al. discloses an adaptive filtering method for reducing noise caused by the stick and slip effects of the rotary table. The system disclosed in the ""206 patent uses measurements of the rotary table torque as a reference input to an adaptive noise canceler. The main signal input to the noise canceler is the measured standpipe pressure. The aim of the noise canceling system disclosed in the Grosso et al. ""206 patent is to reduce the effects of variations in the measured standpipe pressure caused by rotary table stick and slip.
U.S. Pat. No. 5,490,121 issued to Gardner et al. discloses a non-linear adaptive equalizer for reducing non-linear distortion of the telemetry signal. The nonlinear equalizer receives an input signal from a pressure transducer and passes the signal through a bank of non-linear function elements. The signal is then processed by a parallel set of linear, or decision feedback, equalizers. One linear equalizer receives the unmodified input signal as its input, and the other linear equalizers receive their inputs from the output of a nonlinear function element. The output signals of the linear equalizers are summed together to provide the nonlinear equalizer""s output signal.
U.S. Pat. No. 5,969,638 issued to Chin discloses a signal processor for use with MWD systems. The signal processor combines signals from a plurality of signal receivers on the standpipe, spaced less than one-quarter wavelength apart to reduce mud pump noise and reflections traveling in a downhole direction. The signal processor isolates the derivative of the forward traveling wave, i.e., the wave traveling up the drill string, by taking time and spatial derivatives of the wave equation. Demodulation is then based on the derivative of the forward traveling wave. The signal processor requires that the signal receivers be spaced a distance of five to fifteen percent of a typical wavelength apart.
FIG. 2 shows an example of the previously referred to electromagnetic telemetry system used with MWD systems. The measured data are used to modulate an electromagnetic wave instead of the acoustic wave used in mud pulse telemetry. The communications channel is no longer the mud column within the drill string. Electromagnetic telemetry is often used when drilling using xe2x80x9cunder-balancedxe2x80x9d drilling mud. The drilling mud is aerated in typical under-balanced drilling, so that the downhole mud pressure is approximately the same as that of the formation, thus preventing damage to the formation. An electromagnetic transmitter 201 substitutes for the acoustic transmitter (105 in FIG. 1) in the bottom hole assembly. The transmitter 201 generates an electromagnetic wave by producing a time-varying potential difference across an insulating gap 202. The electromagnetic wave propagates through the earth to the surface. The signal at the surface is measured as the potential difference between two or more spaced apart points 210, 212, 214. For example, the surface signal measurement may consist of the difference in electrical potential between that measured at the wellhead 210 and other electrical conductors 212, 214 in contact with the earth at some distance from the wellhead 210. A sensor at the wellhead measures the electrical potential at that point. The sensor sends a signal 211 representative of this electrical potential to the signal processing module 134. A sensor 212 at a second location measures the electrical potential at that second location A signal 213 representative of the electrical potential measured by this second sensor is also sent to the signal processing module 134. The difference in potential between these two locations is representative of the electromagnetic telemetry signal received at the surface. The signal processing module recovers the transmitted symbols and then the data bits.
High power electrical equipment such as the mud pumps 115 and the rotary table""s 154 driving motor can induce electrical currents in the earth near the surface. This electrical noise may also be harmonic in nature and present similar problems to the electromagnetic telemetry as the mud pump noise does for mud pulse telemetry.
One aspect of the invention is a method for reducing noise in a measured telemetry signal. The method according to this aspect includes tracking a characteristic of at least one harmonic of a noise component in the measured telemetry signal. The at least one harmonic has a frequency outside a telemetry signal band. The characteristic of the noise component is determined for at least one other harmonic thereof. The at least one other harmonic has a frequency inside the telemetry signal band. A noise reference is generated from the characteristic of the in band harmonic, and the noise reference is combined with the measured telemetry signal to generate a noise-canceled telemetry signal.
In some embodiments, the characteristic is the instantaneous frequency of the harmonic. In some embodiments, the characteristic is the instantaneous phase. In some embodiments, the characteristic is tracked for a plurality of harmonics having frequencies outside the telemetry signal band.
In some embodiments, the detected telemetry signal is bandpass filtered within the telemetry signal band, and is filtered outside the telemetry signal band prior to the tracking to enhance the generating the noise reference.
In some embodiments, the combining includes adaptive noise canceling. In some embodiments, the combining includes estimating an amplitude and instantaneous phase and frequency of noise components inside the telemetry signal band from the tracked characteristic, reconstructing the noise components inside the telemetry signal band from the estimated amplitude and instantaneous frequency and phase, and summing the reconstructed noise components with the detected telemetry signal.
Other aspects and advantages of the invention will be apparent from the following description and the appended claims.